In drilling a wellbore into the earth, such as for the recovery of hydrocarbons or minerals from a subsurface formation, it is conventional practice to connect a drill bit onto the lower end of a drill string (comprising drill pipe sections connected end-to-end) and then to rotate the drill string (by means of either a “rotary table” or a “top drive” associated with a drilling rig) so that the drill bit progresses downward into the earth to create the desired wellbore.
During the drilling process, a drilling fluid (commonly referred to as “drilling mud,” or simply “mud”) is pumped under pressure downward through the drill string, out the drill bit into the wellbore, and then upward back to the surface through the wellbore annulus between the drill string and the wellbore. The drilling fluid, which may be water-based or oil-based, is typically viscous to enhance its ability to carry wellbore cuttings to the surface. The drilling fluid can perform various other valuable functions, including enhancement of drill bit performance (e.g., by ejection of fluid under pressure through ports in the drill bit, creating mud jets that blast into and weaken the underlying formation in advance of the drill bit), drill bit cooling, and formation of a protective cake on the wellbore wall (to stabilize and seal the wellbore wall). To optimize these functions, it is desirable for as much of the drilling fluid as possible to reach the drill bit.
Particularly since the mid-1980s, it has become increasingly common and desirable in the oil and gas industry to use “directional drilling” techniques to drill horizontal and other non-vertical wellbores, to facilitate more efficient access to, and production from, larger regions of hydrocarbon-bearing formations than would be possible using only vertical wellbores. In directional drilling, specialized drill string components and “bottomhole assemblies” (BHAs) are used to induce, monitor, and control deviations in the path of the drill bit, so as to produce a wellbore of desired non-vertical configuration.
Directional drilling is typically carried out using a “downhole motor” (also referred to as a “mud motor”) incorporated into the drill string immediately above the drill bit. A typical mud motor includes the following primary components (in order, starting from the top of the motor assembly):                a top sub adapted to facilitate connection to the lower end of a drill string (“sub” being the common general term in the oil and gas industry for any small or secondary drill string component);        a power section (commonly comprising a positive displacement motor of well-known type, with a helically-vaned rotor eccentrically rotatable within a stator section, and with a fixed or adjustable straight or bent housing for inducing a wellbore deviation);        a drive shaft enclosed within a drive shaft housing having a central bore for conveying drilling fluid to the drill bit, with the upper end of the drive shaft being operably connected to the rotor of the power section; and        a bearing section comprising a cylindrical mandrel coaxially and rotatably disposed within a cylindrical bearing housing, with an upper end coupled to the lower end of the drive shaft, and a lower end connectable to a drill bit.        
In drilling processes using a mud motor, drilling fluid is circulated under pressure through the drill string and back up to the surface as in conventional drilling methods. However, the pressurized drilling fluid is diverted through the power section of the mud motor to generate power to rotate the drill bit.
The bearing section must permit relative rotation between the mandrel and the housing, while also transferring axial thrust loads between the mandrel and the housing. Axial thrust loads arise in two drilling operational modes: “on-bottom” loading, and “off-bottom” loading. On-bottom loading corresponds to the operational mode during which the drill bit is boring into a subsurface formation under vertical load from the weight of the drill string, which in turn is in compression; in other words, the drill bit is on the bottom of the borehole. Off-bottom loading corresponds to operational modes during which the drill bit is raised off the bottom of the borehole and the drill string is in tension (i.e., when the bit is off the bottom of the borehole and is hanging from the drill string, such as when the drill string is being “tripped” out of the wellbore, or when the wellbore is being reamed in the uphole direction). Tension loads across the bearing section housing and mandrel are also induced when drilling fluid is being circulated while the drill bit is off bottom, due to the pressure drop across the drill bit and bearing assembly
Accordingly, the bearing section of a mud motor must be capable of withstanding thrust loads in both axial directions, with the mandrel rotating inside the bearing housing. Suitable radial bearings are used to maintain coaxial alignment between the mandrel and the bearing housing.
Thrust bearings contained within the bearing section of a mud motor may be either oil-lubricated or mud-lubricated. In an oil-lubricated bearing assembly, the thrust bearings are disposed within a sealed, oil-filled reservoir to provide a clean operating environment. The oil reservoir is located within an annular region between the mandrel and the bearing housing, with the reservoir being defined by the inner surface of the housing and the outer surface of the mandrel, and by sealing elements at the upper and lower ends of the reservoir.
Mud-lubricated bearing assemblies comprise bearings (thrust bearings and/or radial bearings) that are designed for operation in drilling fluid. In conventional mud-lubricated bearings, a portion of the drilling fluid flowing to the drill bit is diverted through the bearings to provide lubrication and cooling, and then is discharged into the wellbore annulus, thus bypassing the bit. This reduces the volume of drilling fluid flowing through the bit, thus reducing the hydraulic energy available for hole cleaning and bit performance.